1. Field of the Invention
This invention pertains to a method and apparatus for providing a fluid communication path in a wellbore and more particularly to a method and apparatus for permitting the combined usage of an auxiliary tubing on a pipe string to pass fluids between the surface and a downhole location and also accurately transmit fluid pressure changes.
2. Description of the Background
It is often desirable to pass a small diameter tubing, hereinafter referred to as capillary tubing, into a borehole to provide communication from the surrface to the bottom of a borehole or vice versa. For example, it may be useful to communicate pressure data from downhole to the surface by transmitting the fluid pressure through a fluid within a small diameter capillary tubing. Such a system is shown in detail in U.S. Pat. No. 3,895,527.
The capillary tubing system was initially developed for such surface recording of bottomhole pressures. This type of installation is becoming a routine system with many installations in operation. The majority of these systems thus far are in wells of ten thousand feet or less in depth, on land rather than offshore, where holes, while not straight, do not have extreme deviations.
Another use of such capillary tubing that is being developed is to transport chemicals from the surface to the bottom of a wellbore to treat the fluids and/or formation from which such fluids are being produced into the wellbore. This use of the capillary tubing as a chemical transmission system for downhole injection of chemicals is a more recent development.
Ever since the inception of corrosion control of wells by chemicals, the continuous injection of inhibitor into the fluid stream has been recognized as the optimum treating method. In surface lines and process plants, corrosion control by continuous application of filming inhibitors or buffering chemicals is a standard procedure. The advantages gained by applying the continuous injection procedure in oil and gas wells has long been recognized and several procedures and equipment configurations have been field tested. The two methods most widely tested are kill string tubing and the injection of inhibitor packer fluid through a bottomhole valve providing a port between the casing annulus and tubing.
The kill string tubing systems have been the most successful. However, the cost of installation and many operational disadvantages have limited applications of the method. Tubing or pipe size used is generally three-fourth inch to one inch in diameter, and in long strings special high strength joints are required. In addition to the added cost of running the tubing, a special wellhead design is necessary. However, in critical wells, the costs are compounded when considering the operational problems caused by the kill string. The string usually prevents the running of tools and instruments, some of which are mandatory in critical offshore operations. Also, the kill string complicates workover operations and in large volume wells will markedly reduce the producing rates. When inhibiting through a kill string, the bottom will generally be equipped with a valve or flow restricting device. At normal treating rates of a pint to a quart of inhibitor per million cubic feet of gas, the inhibitor in the tubing will be subject to well temperatures and pressures for extended periods. This requires the selection of an inhibitor that will remain stable and neither separate nor polymerize under well conditions. While in special cases the kill string method is still used, its many disadvantages will preclude its general application.
Using an inhibitor mixwed with a packer fluid and displacing through a bottomhole injector valve into the tubing, in theory, overcomes the many problems associated with the kill string method. While there have been successful applications of the bottomhole injector valve system, most installations fail soon after the start of application. Since the inhibitor volumes injected at normal producing rates are quite small, the valve ports must have small diameters to prevent gas from being bypassed to the annulus. The principal cause of failure is plugging of the injection ports. The most frequent source of plugging solids will be fines or drilling fluid additives that remain in the annulus after displacing of the packer fluid and setting of the packer. While in theory the system is good, in practice failures have been so frequent that the system would be considered only as a last resort.
Considering field experience, neither of these two methods have warranted continued research and development. However, corrosion engineers in the industry have continued to recognize the need for a downhole inhibitor transmission system for corrosion control in oil and gas wells. Within the last ten years, with the drilling of deeper, hotter, higher pressure reservoirs, producing at high rates, present gas well corrosion control procedures are often inadequate. The limitations of present methods are apparent in offshore operations in the Gulf of Mexico, where failures from corrosion can result in catastrophic blowouts and costly workovers. When the inadequacies of present methods are considered, the necessity of developing a positive downhole chemical transmission procedure becomes obvious.
The three corrosion inhibiting procedures generally used in gas wells are batch, tubing displacement and squeeze. With each of these methods, the objective is to film the tubing wall with an insulating liquid or semiliquid that adheres tightly to the steel. This breaks the current flow circuit through the water between the anodic and cathodic areas of the steel, stopping the electrochemical reaction. The film must be renewed or reinforced periodically; the treating periods being a function of gas velocity, liquids and solids entrained in the flow stream. For shallower depths (less than ten thousand feet) and lower pressures, temperatures and flow rates, these inhibiting methods, along with suitable inhibitors and appropriate treating periods have given good protection. But today, in deep, hot, high velocity and frequently deviated tubing strings, protection is often inadequate. The major problem is probably velocity of the gas and entrained liquids and solids. The inhibitor film is estimated to have a thickness of two mils. At high velocities, the gas and entrained liquids and solids will rapidly erode this thin film. Another problem in hot wells is the tendency of some inhibitors to polymerize to a brittle, glassy film. Where this film has continuity, it affords corrosion protection but, on solidifying, the inhibitor shrinks, leaving cracks and crevice-type holidays. Also, many of these polymerized films lose their adhereence and are readily chipped from the steel. Attempting to control corrosion by any of these methods would require frequent treating, with intervals of as short as once a week being indicated in some wells.
Even if corrosion control could be assured with any of these three procedures, logistic problems, personnel, and equipment requirements and production loss during treating periods are major disadvantages. This is particularly so in offshore operations where transporting large volumes of inhibitor and diluents along with heavy, large pumps is expensive. Also, where treatments are frequent and gas sales demand is equal to field capacity, scheduling of treatments to assure good corrosion control is difficult.
Over the past several years, it became obvious that for efficient economically sound operations an improved corrosion control method was required. The logical solution was to develop a more effective system to continuously transmit the corrosion control chemical to the bottom of the well, and subsequently enter the tubing string.
With the decision to treat by transmission of inhibitor to the bottom of the hole, there were three methods that could be considered. The kill string and bottomhole valve system, as previously discussed, or the use of a capillary tube installed in the annulus. While the capillary system had never been used for transmission of inhibitors, or in deep, highly deviated holes, it had been successfully used pneumatically for surface recording of bottomhole pressures and hydraulically for injection of single component, low viscosity liquids. Most of the installations had been in straight holes at relatively shallow depths. Subsequent developments have solved many of the problems associated with the system.
Advantages of the present system for downhole injection through a capillary tubing include:
1. The capillary system assures delivery of clean, debris free inhibitor to the downhole injection chamber.
2. Capillary volume is small, minimizing time, and well temperature effects on inhibitor.
3. Inhibitor formulas and injection rates can be quickly changed.
4. Design of capillary system minimized possibility of communication between tubing and casing annulus.
5. Capillary can be used for batching of combination treatments, i.e. corrosion and scale inhibitors, foaming agents, cleaning agents, methanol.
Other advantages of the capillary system include: more efficient production, the reduction of capital investment, safer operation, less manpower requirements and, reduction of chemical costs.
Small diameter capillary tubes have been available for a number of years. However, prior to the mid-1970's, the method of forming the capillary tubing limited the length of sections, so that jointing was required when any significant length of a capillary was used. Successful well applications had been made with reasonably long lengths of the jointed capillaries. But it was obvious that long, continuous lengths of capillary tubing would be required before applications in well bores would be generally accepted.
A new tubing forming method was developed to produce continuous coil lengths of four thousand to ten thousand feet of tubing. The tubing is available in alloys such as 316L stainless steel and 825 Incoloy. The Incoloy tubing was developed specifically for highly corrosive conditions, such as geothermal wells where the stainless tubing was inadequate.
The foregoing background information is set forth in even greater detail in a paper #268 presented to the National Association of Corrosion Engineers, Mar. 3-7, 1980, Chicago, Ill., entitled "Corrosion Protection By Downhole Continuous Inhibitor Transmission Via External Capillary".
When such tubular communication, as described above, is used in a borehole, the small diameter tubular member is typically passed along the outside of tubing and attached thereto as the tubing or pipe string is introduced into the borehole. The pipe string is normally made up of pipe sections which are coupled together with threaded connectors formed integrally on each end of the pipe sections to form a pipe joint. Such pipe joints typically form an upset portion on the pipe string. When small diameter tubing is passed along the pipe string, it must necessarily pass over each pipe joint upset. Tubing protectors are used to protect the tubing from wear, particularly as it passes over each pipe joint upset, and also to support the tubing longitudinally on the pipe string.
In providing a chemical transport system, a tube having a diameter on the order of one-fourth inch to three-eighth inch may be necessary in order to move an acceptable quantity of chemical downhole in a given period of time. This diameter tubing is, however, too large to accurately communicate downhole pressure to the surface as is usually accomplished with 0.094 inch OD/0.054 inch ID tubing. Thus, two tubes have been required, one for chemical transport and one for pressure communication.
It is therefore an object of the present invention to provide a new and improved combined system for transporting chemicals between the surface and downhole in a wellbore and for accurately transmitting fluid pressures.